Method and system for stimulating fluid flow in an upwardly oriented oilfield tubular

ABSTRACT

A method for stimulating fluid flow in an upwardly oriented oilfield tubular ( 1, 12 ) comprises heating the tubular along at least part of its length to such a temperature that at least some liquid hydrocarbons, such as crude oil and/or condensates, evaporate and provide a gas lift effect.

BACKGROUND OF THE INVENTION

The invention relates to a method and system for stimulating fluid flowin an upwardly oriented tubular.

It is known to stimulate fluid flow in oilfield tubulars by using pumps,such as beam pumps, Electrical Submersible Pumps (ESPs) and/or injectinglift gas into an upwardly oilfield tubular to reduce the density andthus the hydrostatic pressure drop of the mixture of oil reservoireffluents.

U.S. Pat. Nos. 1,681,523 and 2,350,429 and US patent applicationUS2006/0051080 disclose electrical heaters for inhibiting deposition ofwax, paraffins and other fouling compositions in production tubings ofoil production wells.

U.S. Pat. No. 1,681,523 discloses that air may be injected into theheated production tubing to distribute the heat and lift the heatedcrude oil to the earth surface.

International patent application WO2009/032005 discloses an inlinedownhole heater that is configured to keep paraffinic well effluents ina liquefied state and that can also be utilized to generate steam forconverting heavy hydrocarbons into light hydrocarbons. A limitation ofthis known inline heater is that not all well effluents compriseparaffin and/or water and that it does not evaporate producedhydrocarbon liquids, so that it does not provide a gas lift effect in anoilfield tubular through which no water flows. The known inline heatertherefore only prevents solidification of paraffin and generates steam,whereas paragraph [0044] indicates that it is designed to prevent gaslocking of a downhole production pump, so that it is clearly notdesigned to evaporate liquid hydrocarbons and provide a gas lift effect.

A disadvantage of the known methods for stimulating fluid flow in wellproduction tubings and other inclined oilfield tubulars is that pumpsand lift gas injection systems are complex, expensive and wear prone.The complexity makes them less favourable in extreme conditions such asarctic and/or remote offshore production platforms.

Another disadvantage of known flow stimulation methods is the number ofpotential leak paths or increased intervention/workover frequencies thatresult in increased health, safety or environmental exposure—which is aspecific concern when hydrocarbon reservoirs contain toxic elements likeH₂S.

A further disadvantage of known flow stimulation methods and systems isthat their operating window is constraint for pressure (maximum welldepth, max deepwater depth) for horizontal reach, for deployments inmultilateral well configurations, for maximum and minimum operating andstandby temperatures, for reservoir fluid chemical composition(chlorine, CO₂, H₂S) and for physical properties (sand, viscosity,multiphase pumping limits etc).

There is a need for an improved method and system for stimulating fluidflow in an upwardly oriented oilfield tubular, which does not onlyinhibit deposition of wax, paraffins, hydrates and other foulingcompositions and is less expensive, less wear prone, brings an extendedoperating window, and yields in a safer operations than the knownartificial lift flow stimulation techniques using gas lift injectionand/or Electrical Submersible Pumps (ESPs).

SUMMARY OF THE INVENTION

In accordance with the invention there is provided a method forstimulating fluid flow in an upwardly oriented oilfield tubular throughwhich liquid well effluents comprising liquid hydrocarbons flow in anupward direction, the method comprising heating the tubular along atleast part of its length to such a temperature that at least some liquidhydrocarbons evaporate into vapour bubbles that reduce the density ofthe fluid, hence reduce the hydrostatic pressure drop between reservoirand wellhead, and thus provide a lift gas effect.

The liquid well effluents may comprise at least some natural gas,condensates, crude oil with light oil fractions and/or water, and thewell effluents inside the tubular may be heated along at least part ofthe tubular length to such a temperature that at least some crude oiland/or condensates are evaporated, for example to a temperature above50°, 100° Celsius, or above 200° Celsius. For a typical oil fieldreservoir, due to the decline in hydrostatic pressure while movingtowards earth surface, light oil fractions (e.g. ethane, propane,butane) bubbles already form naturally while the fluid travels againstgravity. The disclosed method aims to accelerate that effect, so thatmore bubbles appear deeper in the well already, resulting in the desiredgas lifting effect without necessarily bringing compressed gas fromsurface back into the well.

For a typical oil well, the reservoir is hotter than the formation rock(and eventually the surface wellhead) temperature. Fluid inside theproduction tubing cools down when travelling upwards, both due to thegeothermal temperature gradient and due to the Joules-Thompson effectwhen hydrostatic pressure decreases. Rather than heating the fluid,systems exploiting the disclosed method often merely need to reduce thiscooling effect in order to trigger or maintain bubble formation at thedesired depths.

The oilfield tubular may be a production tubing within a crude oilproduction well, an inclined underwater oil transportation pipeline oroil production riser at an offshore crude oil production facility, or aninclined crude oil transportation pipeline in possibly a cold or arcticarea.

In accordance with the invention there is further provided a system forenhancing fluid flow in an upwardly oriented oilfield tubular throughwhich liquid well effluents comprising liquid hydrocarbons flow in anupward direction, the system comprising a heater for heating the welleffluents inside a tubular along at least part of its length to such atemperature that at least some liquid hydrocarbons evaporate and providea gas lift effect, which may involve bringing the natural bubbleformation point lower into the well.

In such case the oilfield tubular may be provided with an electricalresistance heater for heating the well effluents at a plurality ofheating locations along at least part of the length of the oilfieldtubular and with a Distributed Property Sensing (DPS) and/or othersensor assembly for measuring the density and/or temperature of the welleffluents at a plurality of measuring locations along at least part ofthe length of the oilfield tubular, wherein at least one of saidmeasuring locations is located upstream of said plurality of heatinglocations and at least one other of said measuring locations is locateddownstream of said plurality of heating locations.

These and other features, embodiments and advantages of the method andsystem according to the invention are described in the accompanyingclaims, abstract and the following detailed description of non-limitingembodiments depicted in the accompanying drawings, in which descriptionreference numerals are used which refer to corresponding referencenumerals that are depicted in the drawings.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1 depicts an upwardly oriented oilfield tubular which is heated toenhance fluid flow by evaporating hydrocarbon well effluents inaccordance with the invention;

FIG. 2 depicts a conventional oil well where lift gas is injected intothe production tubing to provide a gas lift effect; and

FIG. 3 depicts an oil well which is heated to evaporate liquid welleffluents to provide a gas lift effect in accordance with the invention.

DETAILED DESCRIPTION OF THE DEPICTED EMBODIMENT

FIG. 1 depicts an upwardly oriented oilfield tubular 1 through which astream of well effluents flow in an upward direction as illustrated byarrow 2.

An electrical heating cable 3 and a fiber optical DistributedTemperature Sensing (DTS) cable 4 extend in a longitudinal directionalong at least part of the oilfield tubular 1.

By transmitting electrical current through the electrical heating cable3 the well effluents are heated to such a temperature that at least somewell effluent evaporates as illustrated by dotted area 5.

The DTS cable 4 monitors the temperature of the stream of well effluents2 and is connected to an electrical power control unit (not shown) thatcontrols the amount of electrical energy transmitted through theelectrical heating cable 3 such that the temperature of the stream ofwell effluents 2 is elevated to at least the bubble point of that fluid,at the pressure at that elevation, or to another elevated temperature atwhich at least some water, condensates and/or crude oil evaporates andprovides a gas lift effect as illustrated by dotted area 5.

FIGS. 2 and 3 each depict an oil production well comprising a wellcasing 10, having a perforated lower section that permit influx of crudeoil into the well from an oil containing formation 11. A productiontubing 12 is suspended within the well casing 10 and a sealing assembly13 is arranged in an annular space 15 between the well casing 10 andproduction tubing 12 just above the perforated lower section of the wellcasing 10. FIG. 2 shows a conventional gas lift assembly wherein liftgas is injected through a lift gas injection conduit 14 via the annularspace 15 and lift gas injection ports 16 into the interior of theproduction tubing 12.

FIG. 3 shows a lift gas generation assembly according to the inventionwherein an electrical power supply cable assembly 17 is arranged in theannular space 15, which assembly 17 provides electrical power to aseries of electrical resistance heaters 18 arranged in the interior orwrapped around the outer surface of the production tubing 12. Theelectrical heaters 18 are each configured to generate such an amount ofheat in the well effluents flowing through the production tubing 12 thatat least some well effluents, such as water, crude oil and/orcondensates evaporate and generate lift gas that reduces the density ofthe well effluent column within and thereby stimulates and enhances theupward flux of well effluents from the oil containing formation 11through the production tubing 12 to the wellhead at the earth surface.

It will be understood that electrical heaters 18 may evaporate andgenerate lift gas not only in an upwardly oriented production tubing 12of an oil well, but also in an upwardly oriented production tubing of agas well, in which case the electrical heaters 18 may be configured toevaporate any water and condensates flowing through the productiontubing 12, and also in other upwardly oriented oilfield tubular, such arisers of an offshore oil and/or gas production facility, underwaterflowlines at an inclined water bottom, for example subsea to beachflowlines and/or arctic flowlines at a tilted underground or support,provided that the oil and/or gas well effluents flow in an upwarddirection through at least part of the length of the oilfield tubular,which may have any tilt angle from zero up to and including 90° degreesrelative to a horizontal plane, so that the production tubing 12 orother oilfield tubular may have an inclined or vertical orientation.

It will be understood that the term crude oil as used in thisspecification and claims refers to reservoir oil as present in the poresof an underground oil bearing formation, including any changes to thecomposition of the reservoir oil as it travels through the pores of thereservoir to an inflow region of an oil production well and as ittravels through the production tubing of such production well and anygrid of oilfield tubulars at the earth surface which is connected to awellhead of the oil production well.

1. A method for stimulating fluid flow in an upwardly oriented oilfieldtubular through which liquid well effluents comprising liquidhydrocarbons flow in an upward direction, the method comprising heatingthe tubular along at least part of its length to such a temperature thatat least some liquid hydrocarbons evaporate and provide a gas lifteffect.
 2. The method of claim 1, wherein the liquid hydrocarbonscomprise crude oil and gas condensates and the tubular is heated alongat least part of its length to such a temperature that at least somecrude oil and/or gas condensates are evaporated.
 3. The method of claim1, wherein the tubular is heated along at least part of its length to atemperature above 50° Celsius, optionally above 100° Celsius, or above200° Celsius.
 4. The method of claim 1, wherein the oilfield tubular isheated at a first location along its length; a physical property, suchas the temperature, density, pressure, flow rates, gas/liquid ratio ofthe well effluents is measured at a second location, which is locatedupstream of the first location, and at a third location, which islocated downstream of the first location; and the heating at the firstlocation is controlled in response to a difference of the physicalproperties of the well effluents measured at the second and thirdlocations.
 5. The method of claim 1, wherein the well tubular is heatedat a plurality of heating locations along at least part of its lengthand the physical property, such as density, temperature, pressure, flowrate and/or gas/liquid ratio of the well effluents is measured at aplurality of measuring locations along at least part of the length ofthe oilfield tubular, wherein at least one of said measuring locationsis located upstream of said plurality of heating locations and at leastone other of said measuring locations is located downstream of saidplurality of heating locations.
 6. The method of claim 1, wherein theoilfield tubular and the well effluents within the tubular are heated byan electrical resistance heater, which extends along at least part ofthe length of the oilfield tubular.
 7. The method of 1, wherein thephysical property of the well effluents is measured at a plurality oflocations along at least part of the length of the oilfield tubular by afiber optical Distributed Property Sensing (DPS) cable extending alongat least part of the length of the oilfield tubular.
 8. The method ofclaim 6, wherein the electrical resistance heater and fiber optical DPScable extend through the interior of the oilfield tubular.
 9. The methodof 3, wherein the electrical resistance heater and fiber optical DPScable are located outside and located adjacent to an outer surface ofthe oilfield tubular.
 10. The method of claim 8, or wherein theelectrical resistance heater comprises an electrical conductor thattransmits both electric heating power supply and bi-directionalcommunication signals so that longitudinally spaced segments of theelectrical resistance heater and multiple sensors for measuring one ormore physical properties in the vicinity of these segments areindividually addressable.
 11. The method of claim 10, wherein theelectrical conductor comprises an electrical circuit formed by either:a) an electrical supply conductor formed by an electrical cable wire andan electrical return conductor formed by an electrically conductivemetal in the wall of the tubular; b) a pair of co-axial pipes such as awell casing and production tubing, as commonly used in oil or gas wells.12. The method of claim 6, wherein the electrical resistance heatercomprises: a) a series of longitudinally spaced self regulating PositiveTemperature Coefficient (PTC) resistors that safeguard against localoverheating; b) an inductive heating system that inductively heats up ametal wall of the oilfield tubular from either the interior the exteriorof the oilfield tubular; c) a microwave heater that heats up the welleffluents; and/or d) an ohmic resistance heater formed by all or part ofa metal wall of the oilfield tubular that is either galvanicallyisolated segment by segment, or whose power supply is locallygalvanically isolated.
 13. The method of claim 1, wherein the upwardlyoriented oilfield tubular comprises: a) an upwardly oriented productiontubing within a crude oil production well; b) an upwardly orientedunderwater crude oil transportation pipeline or crude oil productionriser at an offshore crude oil production facility; and/or c) anupwardly oriented crude oil transportation pipeline.
 14. A system forenhancing fluid flow in an inclined oilfield tubular through whichliquid reservoir effluents comprising liquid hydrocarbons flow in anupward direction, the system comprising a heater for heating the tubularalong at least part of its length to such a temperature that at leastsome liquid hydrocarbons evaporate and provide a lift gas effect. 15.The system of claim 13, wherein the oilfield tubular is provided with anelectrical resistance heater for heating the well effluents at aplurality of heating locations along at least part of the length of theoilfield tubular and with a Distributed Property Sensing (DPS) and/orother sensor assembly for measuring the density and/or temperatureand/or pressure and/or flow rate and/or gas/liquid ratio of the oilwelleffluents at a plurality of measuring locations along at least part ofthe length of the oilfield tubular, wherein at least one of saidmeasuring locations is located upstream of said plurality of heatinglocations and at least one other of said measuring locations is locateddownstream of said plurality of heating locations.
 16. The system ofclaim 13, wherein the oilfield tubular is a production tubing in gaswell and the well effluents comprise natural gas, condensates and/orwater, and system is configured to reduce hydrostatic pressure dropalong at least part of the length of the production tubing so thatwellhead pressure and well effluent production rate are maintained at anelevated level during the lifecycle of the gas well, thereby reducing aneed for compressors in the well and/or at the earth surface.